Wednesday, April 8, 2015

Cost of solar power (51)

Today I’ll run the numbers on the Xina Solar One project in South Africa.  I anticipate this will be the last of four posts associated with an authoritative report I have recently been reading from the Frankfurt School – UNEP Centre and Bloomberg New Energy Finance on the renewable industry around the world. 

According to internet reports such as this, the Xina Solar One project is a 100 MW parabolic trough plant in Northern Cape Province, South Africa.  Xina Solar One was awarded to Abengoa in the third round of renewable energy projects organised by the Department of Energy in South Africa.  Construction started in December 2014 and is expected to be complete in 2017.  Abengoa controls 40% of the project, the other members of the consortium are the Industrial Development Corporation, Public Investment Corporation and KaXu Community Trust.  Finance has been arranged through a large number of banks and financial institutions, as listed here.

Xina Solar One uses what is nowadays conventional technology.  Molten oil is heated to 395°C in parabolic trough collectors, and the thermal energy is transferred via heat exchanges either to steam for power generation or to molten salts for five hours storage.  The two-tank storage system contains 47,155 tonnes of solar salt, good for 1,650 MWh (thermal) of storage.  That provides for five hours operation, or 500 MWh (electrical), indicating a thermal-electrical efficiency of 500/1,650 = 0.303.

Note that these Rankine-cycle plants with thermal storage need a lot of infrastructure.  This includes the solar collectors, pumps for the heat transfer oil and molten salt, storage tanks, a boiler, heat exchangers for oil-salt, a condenser, and perhaps a facility for pre-heat and reheat of steam.  All that adds to the cost.

According to this report, the cost of the project is ZAR 9.5 billion or USD 867 million as at exchange rates of mid 2014.

What about the annual output?  As is often the case, I need to make an estimate.  The best clue comes from this press release from Abengoa, which says that the output is sufficient for 95,000 households and will avoid emissions of 348,000 tonnes CO2 per year.  Let’s suppose the emissions intensity of the South African generating fleet is 0.90 tonnes per MWh.  That implies the annual emissions are 348,000/0.9 or approximately 387,000 MWh per year.

We can now proceed to analyse the Levelised Cost of Electricity (LCOE) using my standard assumptions:
  • there is no inflation,
  • taxation implications are neglected,
  • projects are funded entirely by debt,
  • all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
  • all projects have the same annual maintenance and operating costs (2% of the total project cost), and
  • government subsidies are neglected.


For further commentary on my LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The results for Xina Solar One are as follows:

Cost per peak Watt              USD 8.67/Wp
LCOE                                     USD 256/MWh

The components of the LCOE are:
Capital           {0.094 × USD 867×106}/{387,000 MWhr} = USD 211/MWhr
O&M              {0.020 × USD 867×106}/{387,000 MWhr} = USD 45/MWhr

By way of comparison, LCOE figures (in appropriate currency per MWh) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear in my index of posts with the title “Cost of solar power ([number])”:

(2)        AUD 183 (Nyngan, Australia, PV)
(3)        EUR 503 (Olmedilla, Spain, PV, 2008)
(3)        EUR 188 (Andasol I, Spain, trough, 2009)
(4)        AUD 236 (Greenough, Australia, PV)
(5)        AUD 397 (Solar Oasis, Australia, dish, 2014?)
(6)        USD 163 (Lazio, Italy, PV)
(7)        AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)
(8)        USD 228 (New Mexico, CdTe thin film PV, 2011)
(9)        EUR 200 (Ibersol, Spain, trough, 2011)
(10)      USD 231 (Ivanpah, California, tower, 2013?)
(11)      CAD 409 (Stardale, Canada, PV, 2012)
(12)      USD 290 (Blythe, California, trough, 2012?)
(13)      AUD 285 (Solar Dawn, Australia, CLFR, 2013?)
(14)      AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)
(15)      EUR 350 (Lieberose, Germany, thin-film PV, 2009)
(16)      EUR 300 (Gemasolar, Spain, tower, 2011)
(17)      EUR 228 (Meuro, Germany, crystalline PV, 2012)
(18)      USD 204 (Crescent Dunes, USA, tower, 2013)
(19)      AUD 316 (University of Queensland, fixed PV, 2011)
(20)      EUR 241 (Ait Baha, Morocco, 1-axis solar thermal, 2012)
(21)      EUR 227 (Shivajinagar Sakri, India, PV, 2012)
(22)      JPY 36,076 (Kagoshima, Kyushu, Japan, PV, start July 2012)
(23)      AUD 249 (NEXTDC, Port Melbourne, PV, Q2 2012)
(24)      USD 319 (Maryland Solar Farm, thin-film PV, Q4 2012)
(25)      EUR 207 (GERO Solarpark, Germany, PV, May 2012)
(26)      AUD 259 (Kamberra Winery, Australia, PV, June 2012)
(27)      EUR 105 (Calera y Chozas, PV, Q4 2012)
(28)      AUD 205 (Nyngan and Broken Hill, thin film PV, end 2014?)
(29)      AUD 342 (City of Sydney, multiple sites, PV, 2012)
(30)      AUD 281 (Uterne, PV, single-axis tracking, 2011)
(31)      JPY 31,448 (Oita, PV?, Japan, to open March 2014)
(32)      USD 342 (Shams, Abu Dhabi, trough, to open early 2013)
(34)      USD 272 (Daggett, California, designed 2010)
(35)      GBP 148 (Wymeswold, UK, PV, March 2013)
(36)      USD 139 (South Georgia, PV, June 2014)
(37)      USD 169 (Antelope Valley, CdTe PV, end 2015)
(38)      AUD 137 (Mugga Lane, PV, mid 2014)
(39)      AUD 163 (Coree, fixed PV, Feb 2015)
(40)      AUD 298 (Ferngrove Winery, PV, July 2013)
(41)      USD 125 (Cerro Dominador, CST, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)
(44)      AUD 304 (Weipa, PV, January 2015)
(45)      AUD 256 (Kalgoorlie-Boulder, PV, August 2014)
(46)      AUD 141 (new Moree Solar Farm, PV, one-axis tracking, December 2015)
(47)      AUD 184 (Brookfarm, PV, December 2015)
(48)      USD 110 (Amanecer, PV, June 2014
(49)      USD 113 (DEWA, PV, April 2016)
(50)      USD 284 (Ashalim, solar thermal, 2017)
(51)      USD 256 (Xina Solar One, solar thermal, 2017)

Conclusion

You can compare results with my LCOE graphic.

On this analysis, the LCOE for Xina Solar One is rather expensive, about twice that for Cerro Dominador in Chile (number 41 in the list above), which is also a solar thermal plant due for completion in 2017.  The LCOE for Xina Solar One is however 10% cheaper than that for Ashalim in Israel, which I analysed yesterday.


My general conclusion is that these solar thermal plants are significantly more expensive than the latest PV plants.  However both Xina and Ashalim have incorporated plans for back-up heating by fossil fuels, which implies the possibility of despatchable power generation.  The thought comes to my mind that it should be possible to make a calculation for the benefit of such co-firing.  I’ll look into that.

Cost of solar power (50)

As mentioned in the two previous posts, I’m currently reading an authoritative report by the Frankfurt School – UNEP Centre and Bloomberg New Energy Finance on the renewable industry around the world. 

From my standpoint, one obvious observation from the report is how out-of-step Australia is with the rest of the world.  There are immensely powerful drivers for growth of renewables in the global economy:
  • energy security
  • new-build infrastructure in developing countries
  • pollution reduction
  • the need to reduce CO2 emissions

The effect of those drivers can be seen in the chart below, which is based on data in Figure 3 of the linked report.  It shows global trends in annual investment in renewables from 2004 to 2014.  The figures in brackets in the legend are the compound average growth rate of global investment in each technology from 2004 to 2014.


So, it is absolutely crystal clear – the global economy is investing heavily in renewables, particular solar and wind.

Is this trend likely to continue?  I refer you to a detailed article by Andy Skuce on the Skeptical Science website today.  His arguments cannot be summarised simply in one or two charts, but the crucial result is that current rates of CO2 emissions are absolutely incompatible with the need to keep the global temperature rise in industrial times to less than 2°C.  Much more investment in renewables will be required than is occurring at present.  A logical conclusion is that the investment trends shown in the chart above are likely to strengthen.

How does the Australian federal government act in the face of these trends?  The government says that switching to renewables will “clobber” our economy, that coal (and only coal!) will lift the developing world out of poverty, and that we should extract and burn every last kilogram of coal that we can. 


However, the price of coal as shown in the chart above (source) does not inspire confidence.  After a long stable period, there was a surge in the price from 2004 onwards.  Helped along by stimulus packages in various countries, notably China, the price surge lasted through the Global Financial Crisis in 2007 up until 2010, at which time the price entered a long steep decline.  Investment in coal does not look like a good strategy to me.

The government also repealed the carbon tax, closed down the Climate Commission, appointed climate change deniers to lead major reports into the economy, wants to close the Climate Change Authority and the Clean Energy Finance Corporation, and is seeking to cut the renewable energy target. 

The outcomes are evident in these quotes from the linked report:

“Small-scale solar financing declined in Australia by 11% [from 2013] as the country found itself mired in policy uncertainty, despite its robust solar resources and well-developed installation industry” (p.23)

“In Australia, utility-scale [renewables] investment plummeted to $330 million [in 2014] – from $2.1 billion in 2013 – largely due to uncertainty over the country’s renewable energy target” (p.25)

In the face of this evidence, is there any rationality or logic in the actions of the Australian government since its election in late 2013?  Well, yes, there is an ugly logic.  The likelihood is that coal will be an even worse investment strategy in the future than it is now.  Hence exploit the coal reserves as fast as possible, and never mind any long-term economic consequences or moral implications about climate change.

To me, the actions of the Australian government since election in late 2013 go beyond political patronage and ideology.  Appropriate descriptors are recklessness and irresponsibility, even economic vandalism.   The Australian people deserve better than this.  As a wealthy developed nation we should be playing a greater role in the global growth of renewables.

Well, that’s my rant for the day.  Let me now analyse the Ashalim 1 solar thermal plant in Israel.

The Ashalim solar project is based in the Negev desert in Israel.  It’s a 121 MW plant, now under construction, and due to be finished in 2017.   The project is being carried out by Megalim Solar Power, a joint venture between Alstom (25.05%), BrightSource (25.05%) and NOY Infrastructure and Energy Investment Fund (49.9%).

The technology is very similar to the Ivanpah Project in the USA (also involving BrightSource) – that is direct steam generation via heliostats and tower, with no thermal storage.  The Capacity Factor of Ivanpah is 31% (source), which implies the annual output of Ashalim will be 0.31 × 121 × 24 × 365 MWh, or approximately 330,000 MWh per year.  Back-up heating by gas is available but capped to 15% of the total output.  The cost of the project is reported as USD 821 million.

We can now proceed to analyse the Levelised Cost of Electricity (LCOE) using my standard assumptions: 
  • there is no inflation,
  • taxation implications are neglected,
  • projects are funded entirely by debt,
  • all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
  • all projects have the same annual maintenance and operating costs (2% of the total project cost), and
  • government subsidies are neglected.

For further commentary on my LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The results for Ashalim are as follows:

Cost per peak Watt              USD 6.78/Wp
LCOE                                     USD 284/MWh

The components of the LCOE are:
Capital           {0.094 × USD 821×106}/{330,000 MWhr} = USD 234/MWhr
O&M              {0.020 × USD 821×106}/{330,000 MWhr} = USD 50/MWhr

By way of comparison, LCOE figures (in appropriate currency per MWh) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear in my index of posts with the title “Cost of solar power ([number])”:

(2)        AUD 183 (Nyngan, Australia, PV)
(3)        EUR 503 (Olmedilla, Spain, PV, 2008)
(3)        EUR 188 (Andasol I, Spain, trough, 2009)
(4)        AUD 236 (Greenough, Australia, PV)
(5)        AUD 397 (Solar Oasis, Australia, dish, 2014?)
(6)        USD 163 (Lazio, Italy, PV)
(7)        AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)
(8)        USD 228 (New Mexico, CdTe thin film PV, 2011)
(9)        EUR 200 (Ibersol, Spain, trough, 2011)
(10)      USD 231 (Ivanpah, California, tower, 2013?)
(11)      CAD 409 (Stardale, Canada, PV, 2012)
(12)      USD 290 (Blythe, California, trough, 2012?)
(13)      AUD 285 (Solar Dawn, Australia, CLFR, 2013?)
(14)      AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)
(15)      EUR 350 (Lieberose, Germany, thin-film PV, 2009)
(16)      EUR 300 (Gemasolar, Spain, tower, 2011)
(17)      EUR 228 (Meuro, Germany, crystalline PV, 2012)
(18)      USD 204 (Crescent Dunes, USA, tower, 2013)
(19)      AUD 316 (University of Queensland, fixed PV, 2011)
(20)      EUR 241 (Ait Baha, Morocco, 1-axis solar thermal, 2012)
(21)      EUR 227 (Shivajinagar Sakri, India, PV, 2012)
(22)      JPY 36,076 (Kagoshima, Kyushu, Japan, PV, start July 2012)
(23)      AUD 249 (NEXTDC, Port Melbourne, PV, Q2 2012)
(24)      USD 319 (Maryland Solar Farm, thin-film PV, Q4 2012)
(25)      EUR 207 (GERO Solarpark, Germany, PV, May 2012)
(26)      AUD 259 (Kamberra Winery, Australia, PV, June 2012)
(27)      EUR 105 (Calera y Chozas, PV, Q4 2012)
(28)      AUD 205 (Nyngan and Broken Hill, thin film PV, end 2014?)
(29)      AUD 342 (City of Sydney, multiple sites, PV, 2012)
(30)      AUD 281 (Uterne, PV, single-axis tracking, 2011)
(31)      JPY 31,448 (Oita, PV?, Japan, to open March 2014)
(32)      USD 342 (Shams, Abu Dhabi, trough, to open early 2013)
(34)      USD 272 (Daggett, California, designed 2010)
(35)      GBP 148 (Wymeswold, UK, PV, March 2013)
(36)      USD 139 (South Georgia, PV, June 2014)
(37)      USD 169 (Antelope Valley, CdTe PV, end 2015)
(38)      AUD 137 (Mugga Lane, PV, mid 2014)
(39)      AUD 163 (Coree, fixed PV, Feb 2015)
(40)      AUD 298 (Ferngrove Winery, PV, July 2013)
(41)      USD 125 (Cerro Dominador, CST, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)
(44)      AUD 304 (Weipa, PV, January 2015)
(45)      AUD 256 (Kalgoorlie-Boulder, PV, August 2014)
(46)      AUD 141 (new Moree Solar Farm, PV, one-axis tracking, December 2015)
(47)      AUD 184 (Brookfarm, PV, December 2015)
(48)      USD 110 (Amanecer, PV, June 2014
(49)      USD 113 (DEWA, PV, April 2016)
(50       USD 284 (Ashalim, solar thermal, 2017)

Conclusion

You can compare results with my LCOE graphic.

On this analysis, the LCOE for the Ashalim plant is rather expensive, about 2.3 times that for Cerro Dominador in Chile (number 41 in the list above), also a solar thermal plant which is due for completion around the same time.  I note that some of the project cost for Ashalim includes construction of a natural gas pipeline for back-up heating, but I doubt that omission of that cost would lower the LCOE by more than 10%. 

Monday, April 6, 2015

Cost of geothermal power (1)

In my last blog post, I mentioned I’ve been reading an authoritative report by the Frankfurt School – UNEP Centre and Bloomberg New Energy Finance on the renewable industry around the world.  The report is full of interesting information, including details of a major geothermal project in Indonesia, which is the topic of today’s post.

Indonesia is reckoned to have more than 29 GW of geothermal generation potential (equivalent to 40% of the global geothermal resource base), although only 1.3 GW is currently installed.  Once completed, the 320 MW Sarulla geothermal project will be the largest such power project in the world.

This report by the Asian Development Bank and other agencies provides an excellent overview of the Sarulla geothermal project.  The project is located in the North Sumatra province of the Republic of Indonesia.  Financial arrangements for the USD 1.6 billion project were signed off on 28 March 2014.  Key project sponsors are Itochu Corporation (25%), Kyushu Electric Power Company (25%), PT Medco Power Indonesia (37.5%) and Ormat International (12.75%).  Funds were arranged through a consortium of about 10 banks, mainly Japanese, but also including Société Générale and National Australia Bank.

From a technological point of view, geothermal heat will drive conventional Rankine-cycle steam turbines.  Halliburton will do the drilling to access the geothermal energy, Hyundai Engineering is responsible for procurement and construction, Toshiba will provide the turbines and Ormat Technologies will provide power converters.

The cost of the project is known (USD 1.6 billion), but what about the annual output?  Again I have to resort to an estimate. 

On the one hand, the project is said to provide baseload power.  If the Capacity Factor is 50% (perhaps a lowball estimate?), then the annual output will be 0.5 × 320 × 365 × 24 MWh or 1,402,000 MWh approximately.

On the other hand, the cited report says the project will save on 1.3 million tonnes of CO2 emissions per year.  Indonesia does not have the most modern fleet of power stations, so let’s assume an emissions intensity of 0.95 tonne CO2 per MWh.  That implies an approximate annual output of 1,368,000 MWh.  I’m inclined to accept that figure.

We can now proceed to analyse the LCOE using my standard assumptions:
  • there is no inflation,
  • taxation implications are neglected,
  • projects are funded entirely by debt,
  • all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
  • all projects have the same annual maintenance and operating costs (2% of the total project cost), and
  • government subsidies are neglected.


For further commentary on my LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The results for the Sarulla project are as follows:

Cost per peak Watt              USD 5.00/Wp
LCOE                                     USD 133/MWh

The components of the LCOE are:
Capital           {0.094 × USD 1.6×109}/{1,368,000 MWhr} = USD 110/MWhr
O&M              {0.020 × USD 1.6×109}/{1,368,000 MWhr} = USD 23/MWhr

Conclusion

My LCOE graphic enables you to compare this geothermal result with the LCOE for various solar projects around the world.  I would say the Sarulla geothermal LCOE result is broadly comparable to current best practice in solar PV projects.


You might also be interested in a comparison with tidal power.  In February 2014, I analysed the LCOE for the Swansea Tidal Lagoon.  That LCOE, based on the same methodology, was USD 326 per MWh, some 2.45 times higher than that for Sarulla geothermal project.  The main reason for this discrepancy in LCOE is the Capacity Factor (rather than the capital cost).

Wednesday, April 1, 2015

Cost of solar power (49)

Lately I’ve been reading an authoritative report by the Frankfurt School – UNEP Centre and Bloomberg New Energy Finance on the renewable industry around the world.  The picture that emerges is of an unstoppable rise of solar power, mainly PV, with a compound average growth rate in investment of 29% from 2004 to 2014.  Worldwide in 2014, 46 GW of new solar capacity was added and the total investment in solar projects was USD 149.6 billion.

One topic that caught my eye in the report is the Levelised Cost of Electricity (LCOE) for a proposed 200 MW PV plant to be built for the Dubai Electricity and Water Authority, DEWA.  The quoted figure is USD 59.8 per MWh, which is said to be the lowest figure ever from an Independent Power Producer for a utility-scale PV project.  The project is due for completion in April 2017.

In this post, I’ll compare the above figure with the LCOE calculated using my standard methodology.

Another report shows this project was vigorously contested, with 49 bidders receiving qualification documents for the tender process.  Of those, 24 were invited to submit a bid and 10 proposals were eventually submitted.  In the end, a consortium led by Saudi firm ACWA Power and Spanish developer TSK was announced as the winner of the process.  The PV panels will be from First Solar.

Unusually, the cost of the project is crystal clear.  DEWA recently signed a contract for loans totalling USD 344 million, said to represent 86% of the cost of the project.  So the total project cost is USD 344 million/0.86 = USD 400 million, perhaps a suspiciously round number.

But, as is not infrequently the case, the annual output of the proposed system is not publicly available, so I need to use an estimate for the Capacity Factor for the project.  Dubai is at latitude 25°N and has a dry sunny climate.  It should be an excellent site for solar energy.  Let me assume the panels are fixed (I couldn’t find any technical details in reports I read) and that the Capacity Factor is 0.23, which represents an educated guess based on other projects I have examined.  So the annual output will be 0.23 × 200 × 365 × 24 = 403 GWh approximately.

We can now proceed to analyse the LCOE using my standard assumptions:

  • there is no inflation,
  • taxation implications are neglected,
  • projects are funded entirely by debt,
  • all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
  • all projects have the same annual maintenance and operating costs (2% of the total project cost), and
  • government subsidies are neglected.


For further commentary on my LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The results for the DEWA project are as follows:

Cost per peak Watt              USD 2.00/Wp
LCOE                                     USD 113/MWh

The components of the LCOE are:
Capital           {0.094 × USD 400×106}/{403,000 MWhr} = USD 93/MWhr
O&M              {0.020 × USD 400×106}/{403,000 MWhr} = USD 20/MWhr

By way of comparison, LCOE figures (in appropriate currency per MWh) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear in my index of posts with the title “Cost of solar power ([number])”:

(2)        AUD 183 (Nyngan, Australia, PV)
(3)        EUR 503 (Olmedilla, Spain, PV, 2008)
(3)        EUR 188 (Andasol I, Spain, trough, 2009)
(4)        AUD 236 (Greenough, Australia, PV)
(5)        AUD 397 (Solar Oasis, Australia, dish, 2014?)
(6)        USD 163 (Lazio, Italy, PV)
(7)        AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)
(8)        USD 228 (New Mexico, CdTe thin film PV, 2011)
(9)        EUR 200 (Ibersol, Spain, trough, 2011)
(10)      USD 231 (Ivanpah, California, tower, 2013?)
(11)      CAD 409 (Stardale, Canada, PV, 2012)
(12)      USD 290 (Blythe, California, trough, 2012?)
(13)      AUD 285 (Solar Dawn, Australia, CLFR, 2013?)
(14)      AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)
(15)      EUR 350 (Lieberose, Germany, thin-film PV, 2009)
(16)      EUR 300 (Gemasolar, Spain, tower, 2011)
(17)      EUR 228 (Meuro, Germany, crystalline PV, 2012)
(18)      USD 204 (Crescent Dunes, USA, tower, 2013)
(19)      AUD 316 (University of Queensland, fixed PV, 2011)
(20)      EUR 241 (Ait Baha, Morocco, 1-axis solar thermal, 2012)
(21)      EUR 227 (Shivajinagar Sakri, India, PV, 2012)
(22)      JPY 36,076 (Kagoshima, Kyushu, Japan, PV, start July 2012)
(23)      AUD 249 (NEXTDC, Port Melbourne, PV, Q2 2012)
(24)      USD 319 (Maryland Solar Farm, thin-film PV, Q4 2012)
(25)      EUR 207 (GERO Solarpark, Germany, PV, May 2012)
(26)      AUD 259 (Kamberra Winery, Australia, PV, June 2012)
(27)      EUR 105 (Calera y Chozas, PV, Q4 2012)
(28)      AUD 205 (Nyngan and Broken Hill, thin film PV, end 2014?)
(29)      AUD 342 (City of Sydney, multiple sites, PV, 2012)
(30)      AUD 281 (Uterne, PV, single-axis tracking, 2011)
(31)      JPY 31,448 (Oita, PV?, Japan, to open March 2014)
(32)      USD 342 (Shams, Abu Dhabi, trough, to open early 2013)
(34)      USD 272 (Daggett, California, designed 2010)
(35)      GBP 148 (Wymeswold, UK, PV, March 2013)
(36)      USD 139 (South Georgia, PV, June 2014)
(37)      USD 169 (Antelope Valley, CdTe PV, end 2015)
(38)      AUD 137 (Mugga Lane, PV, mid 2014)
(39)      AUD 163 (Coree, fixed PV, Feb 2015)
(40)      AUD 298 (Ferngrove Winery, PV, July 2013)
(41)      USD 125 (Cerro Dominador, CST, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)
(44)      AUD 304 (Weipa, PV, January 2015)
(45)      AUD 256 (Kalgoorlie-Boulder, PV, August 2014)
(46)      AUD 141 (new Moree Solar Farm, PV, one-axis tracking, December 2015)
(47)      AUD 184 (Brookfarm, PV, December 2015)
(48)      USD 110 (Amanecer, PV, June 2014
(49)      USD 113 (DEWA, PV, April 2016)


Conclusion

You can compare results with my LCOE graphic.

Bearing in mind (1) the uncertainty with my estimate for the annual output and (2) when the projects are completed, the LCOE for the Dubai project is about the same as the best project I have analysed so far, namely the Amanecer project in the Atacama desert.  The cost per peak Watt for DEWA is less than for Amanecer, but the Capacity Factor is not as good.  As I wrote in my previous post, the Atacama desert has the world’s best solar resources.

Also, my LCOE estimate for the DEWA project (USD 113/MWh) is 89% greater than the LCOE quoted in the press reports.  How can this be?  Well, the financing of utility-scale projects is a secret process – who knows what interest rates are really applicable, whether there are hidden government subsidies and what taxation regimes are applicable?  That’s why I compare the LCOE for renewables projects using a standard set of assumptions, thereby giving the list of results shown above and in the LCOE graphic.

You can be sure that the price of large-scale PV is continuing to fall.  Fossil fuel proponents would do well not to ignore these obvious and mighty trends.

Wednesday, January 28, 2015

Cost of solar power (48)

According to charts available at this website, the Atacama Desert has the best solar resource in the world, as much as 3,500 kWh/m^2 per year.  Moreover this solar resource occurs in a region with significant electricity demand from mining and metal processing operations.  Couple that with all the usual drivers for renewable energy (decarbonisation, price reduction in PV systems, energy security, …) and it’s no surprise that there is now significant solar power generation activity in the Atacama Desert.

The 100 MW Amanecer PV plant in the Copiapo municipality was opened on 8 June 2014.  At the time of opening it was the largest PV plant in South America.  The 280 Ha installation is at an altitude of 1,165 m above sea level, comprises 310,000 Sun Edison panels and will provide 270 GWh of electricity to the local grid.  Construction took only 6 months.

The output of the plant will provide 15% of the local electricity demand of the Chilean steel group CAP, the largest iron ore and pellet producer on the American Pacific Coast.  The cost of the plant has been variously reported as USD 250 million and USD 260.5 million, the latter figure seeming the more authoritative.

We can now proceed to analyse the LCOE using my standard assumptions:
  • there is no inflation,
  • taxation implications are neglected,
  • projects are funded entirely by debt,
  • all projects have the same interest rate (8%) and payback period (25 years), which means that the required rate of capital return is 9.4%,
  • all projects have the same annual maintenance and operating costs (2% of the total project cost), and
  • government subsidies are neglected.

For further commentary on my LCOE methodology, see posts on Real cost of coal-fired power, LEC – the accountant’s view, Cost of solar power (10) and (especially) Yet more on LEC.  Note that I am now using annual maintenance costs of 2% rather than 3% as in posts during 2011.

The results for the Amanecer project are as follows:

Cost per peak Watt              USD 2.61/Wp
LCOE                                     USD 110/MWh

The components of the LCOE are:
Capital           {0.094 × USD 260.6×106}/{270,000 MWhr} = USD 91/MWhr
O&M              {0.020 × USD 260.6×106}/{270,000 MWhr} = USD 19/MWhr

By way of comparison, LCOE figures (in appropriate currency per MWh) for all projects I’ve investigated are given below.  The number in brackets is the reference to the blog post, all of which appear in my index of posts with the title “Cost of solar power ([number])”:

(2)        AUD 183 (Nyngan, Australia, PV)
(3)        EUR 503 (Olmedilla, Spain, PV, 2008)
(3)        EUR 188 (Andasol I, Spain, trough, 2009)
(4)        AUD 236 (Greenough, Australia, PV)
(5)        AUD 397 (Solar Oasis, Australia, dish, 2014?)
(6)        USD 163 (Lazio, Italy, PV)
(7)        AUD 271 (Kogan Creek, Australia, CLFR pre-heat, 2012?)
(8)        USD 228 (New Mexico, CdTe thin film PV, 2011)
(9)        EUR 200 (Ibersol, Spain, trough, 2011)
(10)      USD 231 (Ivanpah, California, tower, 2013?)
(11)      CAD 409 (Stardale, Canada, PV, 2012)
(12)      USD 290 (Blythe, California, trough, 2012?)
(13)      AUD 285 (Solar Dawn, Australia, CLFR, 2013?)
(14)      AUD 263 (Moree Solar Farm, Australia, single-axis PV, 2013?)
(15)      EUR 350 (Lieberose, Germany, thin-film PV, 2009)
(16)      EUR 300 (Gemasolar, Spain, tower, 2011)
(17)      EUR 228 (Meuro, Germany, crystalline PV, 2012)
(18)      USD 204 (Crescent Dunes, USA, tower, 2013)
(19)      AUD 316 (University of Queensland, fixed PV, 2011)
(20)      EUR 241 (Ait Baha, Morocco, 1-axis solar thermal, 2012)
(21)      EUR 227 (Shivajinagar Sakri, India, PV, 2012)
(22)      JPY 36,076 (Kagoshima, Kyushu, Japan, PV, start July 2012)
(23)      AUD 249 (NEXTDC, Port Melbourne, PV, Q2 2012)
(24)      USD 319 (Maryland Solar Farm, thin-film PV, Q4 2012)
(25)      EUR 207 (GERO Solarpark, Germany, PV, May 2012)
(26)      AUD 259 (Kamberra Winery, Australia, PV, June 2012)
(27)      EUR 105 (Calera y Chozas, PV, Q4 2012)
(28)      AUD 205 (Nyngan and Broken Hill, thin film PV, end 2014?)
(29)      AUD 342 (City of Sydney, multiple sites, PV, 2012)
(30)      AUD 281 (Uterne, PV, single-axis tracking, 2011)
(31)      JPY 31,448 (Oita, PV?, Japan, to open March 2014)
(32)      USD 342 (Shams, Abu Dhabi, trough, to open early 2013)
(34)      USD 272 (Daggett, California, designed 2010)
(35)      GBP 148 (Wymeswold, UK, PV, March 2013)
(36)      USD 139 (South Georgia, PV, June 2014)
(37)      USD 169 (Antelope Valley, CdTe PV, end 2015)
(38)      AUD 137 (Mugga Lane, PV, mid 2014)
(39)      AUD 163 (Coree, fixed PV, Feb 2015)
(40)      AUD 298 (Ferngrove Winery, PV, July 2013)
(41)      USD 125 (Cerro Dominador, CST, mid 2017)
(42)      USD 190 (La Paz, PV, September 2013)
(43)      USD 152 (Austin Energy, PV, 2016)
(44)      AUD 304 (Weipa, PV, January 2015)
(45)      AUD 256 (Kalgoorlie-Boulder, PV, August 2014)
(46)      AUD 141 (new Moree Solar Farm, PV, one-axis tracking, December 2015)
(47)      AUD 184 (Brookfarm, PV, December 2015)
(48)      USD 110 (Amanecer, PV, June 2014

Conclusion

You can compare results with my LCOE graphic.

The LCOE for the Amanecer project is outstanding, the best I have analysed so far.  The installation cost per peak Watt (USD 2.61/Wp) is nothing special these days, but the annual output is superb.   I calculate the Capacity Factor as 270,000 / (100×365×24) = 0.308.
 
That’s what one should expect with the best solar resource in the world!